Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on efficiencies associated with well completions and maintenance over the life of the well. Over the years, ever increasing well depths and sophisticated architecture have made reductions in time and effort spent in completions and maintenance operations of even greater focus. Similarly, added focus is also placed on well testing and functionality from the outset of completions and into early well operations, for example, to ensure reliable well control is has been achieved.
In terms of architecture, the terminal end of a cased well often extends into an open-hole section. Thus, completions hardware will generally include lower completions installation at this section. This may include installation of an assembly that includes screen equipment, a gravel packer, frac sleeve and other features. A well control valve may also be installed in conjunction with or immediately after the lower completion. This will be followed by installation of upper completions hardware. The upper completions hardware may include production tubing or hardware supporting zonal isolation that is located above the open-hole section as well as other features such as chemical injection or power and communication lines. Regardless, once the completions hardware is fully installed, testing may take place to ensure reliable well control is has been achieved. For example, the architecture may be configured with the production tubing being isolated within an annulus of the casing and providing a controlled fluid conduit to the control valve, lower completion and surrounding formation. Thus, pressure testing the interior of the production tubing as well as the annulus may be desirable before the production tubing is relied upon for production operations. This way, a controlled uptake of hydrocarbons from the well and through the production tubing may be better assured.
Certain locations of the completions architecture may be more prone than others to develop leaks. For example, isolating packers or the control valve governing access to the lower completions are generally more reliable in maintaining well control than locations where a testing gauge has been incorporated into tubular hardware. That is, for sake of testing and monitoring pressure, temperature, flow and other well characteristics, a test gauge may be incorporated into production tubing of the completions hardware. More specifically, the test gauge may be located at a tubular gauge carrier of limited length that is itself incorporated into production tubing. In this way, an operator may manually assemble the gauge and carrier device at the oilfield surface or platform. Then, much longer production tubing sections may be coupled to each end of the carrier and deployed in conjunction with upper completions as described above.
While such a test gauge may be adept at simultaneously providing a host of readings, both from within the production tubular as well as from the surrounding isolated annulus, as noted above, it may also more susceptible to develop a leak. For example, the gauge is generally an intricate electronic and handheld package, small enough to be manually secured at a location that is otherwise open to both annular and bore sides of the carrier. Indeed, unlike an inflatable packer or other high pressure sealing device, whether or not a downhole leak develops at the location of the gauge is often ultimately a matter of how well the operator positions and tightens the gauge in place at the carrier. That is, unlike a mechanical or inflatable packer, no follow-on downhole actuation is available to ensure a maximum seal is achieved between the gauge and carrier.
Regardless of whether a leak occurs at a gauge location as described above or elsewhere, the consequences of lost well control which results are quite significant. For example, even if a leak is detected during initial testing, there is generally a need for removing at least upper completions hardware and performing a workover. In the case of land-based oilfield operations this may run upwards of 10 million dollars, not counting lost production time. At the other end of the spectrum, a loss of well control during subsea operations may approach 20 million dollars or more in workover expenses.
Given the potential expenses involved and the increased susceptibility to leakage faced by the gauge and gauge carrier device, surface testing of the assembled device generally takes place before the device is deployed into the well with the production tubing. For example, the gauge itself may be rated to withstand 10,000 PSI with a 10-15 year lifespan, depending on well conditions and operations. Of course this still requires a proper seal be attained during manual assembly of the device.
In addition to surface testing of the assembled gauge carrier, efforts have been undertaken to further ensure adequate sealing between the gauge and the carrier. For example, given that the interface of the gauge and carrier is susceptible to leakage emerging from both the inner bore side of the tubular carrier as well as the external annular side, multiple seals may be placed at the interface. However, this results in the unique circumstance of being unable to independently check the multiple seals on a one by one basis. That is, while use of more than one seal may theoretically reduce the likelihood of leakage, if only one of the seals is faulty, there is no conventional way to diagnose the issue. This is because, during surface testing, the remaining non-faulty seal(s) prevent the leak from being perceptible. In such circumstances, the advantage of utilizing an added seal is now lost without the operator being provided any advance warning prior to deployment of the gauge carrier into the well.